Pushing for growth · page 9 Buccaneer amending oil discharge plan for two Cosmopolitan wells...

Buccaneer amending oil dischargeplan for two Cosmopolitan wells

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Vol. 17, No. 49 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of December 2, 2012 • $2

Inside: Petroleum News Bakken


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Vol. 1, No. 16 • www.PetroleumNewsBakken.com A semi-monthly newspaper for industry and government December 2, 2012

B A K K E Npage10

Statoil running 18 rigs in Bakken, goal 100% recycled water for fracking

Despite a “robust outlook for crude supply growth” in the WillistonBasin’s Bakken petroleum system, Oneok “did not receive sufficientlong-term commitments” from shippers under the “terms it neededto construct the Bakken Crude Express Pipeline,” company PresidentTerry K. Spencer said. See full story on page 5 of this issue.

Bakken Express pipeline scrubbed

Saddle Butte out: Targa buysWilliston Basin infrastructure

Houston-based midstream Targa Resources Partners recentlyannounced that it has entered into an agreement with Colorado-based Saddle Butte Pipeline to purchase 100 percent of SaddleButte’s Williston Basin crude oil pipeline and terminal system aswell as its natural gas gathering and processing operations for$950 million.

Saddle Butte was formed in 2009 as a privately held, fullservice midstream company that provided crude oil, natural gas,natural gas liquids and produced water services in the WillistonBasin.

Its assets are all in McKenzie, Dunn and Mountrail countiesof North Dakota, and include the two Saddle Butte terminals,one at Johnsons Corner Terminal, which delivers to BridgerPipeline’s Four Bears line, and the other at Alexander, which

Oxy’s Williston Basin unitabsorbed by Mid-Continent

Joseph R. DeDominic, president and general manager ofOccidental Petroleum’s Williston business unit, left the companyin November to take a position with Eagle Ford player SanchezEnergy as its senior vice president and chief operating officer.

“With Joe’s departure, our Williston business unit has beenabsorbed into our Mid-Continent business unit,” Nancy Turner,Oxy’s director of communications and public affairs, toldPetroleum News Bakken Nov. 28.

The Mid-Continent business unit’s president and generalmanager, Ron Brokmeyer, is based in Houston, she said.

DeDominic “led the acquisition and growth of Oxy’s Bakkenand Three Forks assets in North Dakota,” Sanchez said Nov. 28.

Oxy is currently running five rigs in Dunn County, N.D., upfrom four rigs in October. The Los Angeles-based major once

see TARGA DEAL page 20

see OXY UNIT page 17

Confident if prices slumpHelms: ND production could be sustained with just 50 rigs, 550 new wells per year

By RAY TYSONPetroleum News Bakken

North Dakota oil production could be sus-tained at current record levels even if “the

worst of worst happens,” such as a major downturnin commodity prices, said Lynn Helms, director ofthe state’s Department of Mineral Resources.

Helms said in a Nov. 20 Webcast that it wouldtake only about 50 drilling rigs, or just over a quar-ter of the current fleet, and around 550 new wellsper year to keep production at current levels ofaround 730,000 barrels per day. Currently, nearly200 wells are being added per month alone.

Helms noted that the five top producing coun-

ties in North Dakota would be able to sustain theirrig counts should oil prices drop well below $50 abarrel.

Moreover, even if drilling came to halt outsidethe five leading counties, he said, there still wouldbe about 140 rigs left in the state operating at10,000-15,000 barrels per day, “from now until wesee a price recovery.”

“So we are very confident that we can sustaincurrent production even under some pretty (diffi-cult) scenarios,” Helms said.

Helms sees 3-5% growth rateBut “our best guess” is that North Dakota oil

see ND PRODUCTION page 18

ND’s gas woesState says might take until end of decade to resolve flaring problem

By RAY TYSONPetroleum News Bakken

F inding a solution to North Dakota’sballooning gas-flaring problem will

require a “very difficult balancing act”that could take until the end of thedecade to work out.

“We have to balance the ability tobuild gathering systems against the wastethat takes place with flaring,” LynnHelms, director of the state’s Department ofMineral Resources, said in a Nov. 20 Webcast.

“So we’re looking at toward the end of thisdecade before we really get this flaring dynamicunder control.”

Gas production continues to increaseat a faster rate than the more desirablecrude oil, setting yet another productionrecord in September at 793,546 thousandcubic feet, mcf, per day. Average oil out-put for the month was 728,494 barrelsper day, also a record.

Bakken’s mounting gas volumesBy the time oil production reaches 1

million barrels per day, projected tooccur in 2013 or 2014, the associated gas willamount to around 2 billion cubic feet per day, ahuge volume that has state regulators concerned.

LYNN HELMS

see GAS WOES page 19

US to surpass S. Arabia?Mark Papa says it’s just ‘a whole lot of talk;’ David Roberts, ‘I don’t see it’

By KAY CASHMANPetroleum News Bakken

Recent predictions by theInternational Energy

Agency that U.S. oil produc-tion will rise by 3.3 millionbarrels per day over the nextfive years to 11.4 million bpd,making the U.S. the biggest oilproducer in the world around2017, met with strong disbelief by two oil companyexecutives.

EOG Resources and Marathon Oil are both topproducers in the country’s two strongest tight oilplays; in fact, EOG was a leader in U.S. shale gas and

then tight oil well design anddevelopment. IEA shows tightoil as driving the increase inU.S. oil production.

Although EOG Chairmanand Chief Executive OfficerMark Papa did not specificallymention IEA in a Nov. 28 pres-entation, he did explain hisown company’s projections ofan increase of just 2 million

barrels of oil a day from new U.S. tight and shale oilproduction by 2015, which the U.S. EnergyInformation Administration forecast in June as a

see US PRODUCTION page 12

MARK PAPA DAVID ROBERTS JR.

Pushing for growthHilcorp increases oil production in its newly acquired Cook Inlet fields

By ALAN BAILEYPetroleum News

Since acquiring Chevron’s Cook Inletassets at the beginning of the year,

Hilcorp Energy has been forging aheadwith ambitious plans to breathe new lifeinto the aging oil and gas fields of the CookInlet basin.

“We got the keys tossed to us on Jan. 1and we’ve been up and running ever since,”Greg Lalicker, president of Hilcorp, told the ResourceDevelopment Council’s annual Alaska ResourcesConference on Nov. 14. Lalicker said that oil produc-tion has increased from the oil fields which Hilcorpoperates in the Cook Inlet basin since his company’s

takeover of the Chevron assets.

Business modelHilcorp’s business model revolves

around the squeezing of additional oil andgas from old fields, with those fieldsoften being bought from major oil com-panies, Lalicker said. He likened his com-pany’s business model to a hamster wheelwith a rim consisting of a cycle of proper-ty acquisition, property development and

efficient field production. The speed with which thehamster wheel turns determines the rate of companygrowth, although the company likes slow but steadygrowth at around 15 percent per year, Lalicker said.

GREG LALICKER

see HILCORP GROWTH page 13

Flint Hills drops LNGRefiner cites improved economics, reluctance to lead in solving energy problems

By ERIC LIDJIFor Petroleum News

Although still amenable to using natural gas,Flint Hills Resources LLC is backing away

from leading a project to truck liquefied naturalgas from the North Slope to the Interior.

The refiner recently terminated its memoran-dum of understanding with the electric utilityGolden Valley Electric Association, citing theimproved economics of its internal energy use aswell as the belief that a third party should be lead-ing any efforts going forward.

“Flint Hills still believes LNG trucking is avaluable project for Fairbanks and Interior Alaska,”Flint Hills Resources Alaska Vice President Mike

Brose said in a statement. “However, there are anumber of other entities that have expressed inter-est in this project, and we think the time is right fora third party to determine if there is sufficient sup-port for the project outside of the industrialdemand that Flint Hills has been targeting.”

The announcement came as Flint Hills also said

The Flint Hills refinery uses electricityproduced by GVEA. The GVEA plant inNorth Pole runs on naphtha produced by

Flint Hills (but was designed to alsooperate on natural gas).

see LNG PROJECT page 15

Native opposition buildsFirst Nations across Canada attempt to stall Northern Gateway, Kitimat, Enbridge

By GARY PARKFor Petroleum News

Awave of aboriginal attempts to disrupt majorenergy projects is spreading across Canada.

A little-known First Nations community innorthwestern British Columbia evicted surveyorswho were working on a pipeline linked to theKitimat LNG project, while activists from a FirstNation in southern Ontario have threatened tostage protests against Enbridge plans to move morecrude from Western Canada and the Bakken torefineries in Ontario and Quebec.

The ability of First Nations to slow progress onprojects has become evident this year as communi-ties across northern British Columbia have mount-ed their case against Enbridge’s Northern Gateway

plan during an environmental review.Partly because of the efforts to hijack those

hearings, the joint panel of the National EnergyBoard and the Canadian EnvironmentalAssessment Agency has been forced to extend thehearings by another 10 weeks.

The public hearings that started in January weresupposed to have ended in mid-November, but willnow resume in Prince Rupert on Dec. 10, followed

see NATIVE OPPOSITION page 14

The consulting firm of Deloitte hasestimated that Canadian producers are

losing C$25 billion a year fromtransportation bottlenecks.

Forecast of U.S. oil supremacydraws wide notice, and doubts

The Paris-based International Energy Agency created quitea stir Nov. 12 with the launch of its 2012 World EnergyOutlook.

The report made global headlines with some startling pre-dictions about U.S. oil and gas production.

The recent rebound in U.S. production is driven by upstreamtechnologies that are unlocking light tight oil and shale gasresources, the IEA report said.

By around 2020, the United States is projected to becomethe largest global oil producer, overtaking Saudi Arabia until themid-2020s, the report said.

Concurrently, the country will start to see the impact of new

RCA pledges to make decisionby Dec. 14 on Koch TAPS transfer

The Regulatory Commission of Alaska says it will decide byDec. 14 whether to approve the transfer of Koch’s small owner-ship interest in the trans-Alaska pipeline system to the line’sthree major owners, BP, ConocoPhillips and ExxonMobil.

Meantime, the RCA recently refereed a minor conflict overUnocal’s attempt to intervene in the matter. Unocal is the fifthand final owner in TAPS.

The 800-mile trans-Alaska pipeline carries North Slopecrude oil to the tanker port at Valdez.

Koch Alaska Pipeline Company LLC, a unit of KochIndustries of Wichita, Kan., owns a 3.0845 percent stake inTAPS.

On Oct. 22, Koch, BP, ConocoPhillips and ExxonMobil fileda joint application with the RCA to transfer operating authority

see TAPS TRANSFER page 15

see IEA OUTLOOK page 16

JUD

Y P

ATR

ICK

http://www.PetroleumNews.com/

2 PETROLEUM NEWS • WEEK OF DECEMBER 2, 2012

Petroleum News North America’s source for oil and gas news

FINANCE & ECONOMY

EXPLORATION & PRODUCTION

ENVIRONMENT & SAFETY

7 Cook Inlet Energy seeks lease expansion

Company wants acreage added to Mental Health Trustlease on west side near Tyonek, proposes drilling2 wells over next 2 years

8 Utilities improve efficiency at a cost

New Southcentral Alaska power generation will reducelong-term fuel needs while triggering price increases in the near future

5 Alyeska loses to state on ROW valuation

Alaska Supreme Court affirms Superior Court on DNR2002 appraisal of value of trans-Alaska oil pipeline state right-of-way leases

6 Myers argues for UAF oil spill research

Says that oil development and other Arctic offshore activities will drive a need for innovative spill response technologies

4 U.S. suspends BP federal contracting

EPA cites company’s criminal prosecution for DeepwaterHorizon as basis for action; BP stresses suspension is temporary, limited

NATURAL GAS

contents

11 BP advances planned sale of TNK-BP stake

11 U.S. backs XL: poll

11 Itta named to Arctic Research Commission

10 LNG pipeline may dodge review

10 First Nations lose oil sands case

GOVERNMENT

UTILITIES

9 Buccaneer permitting Cosmo wells

4 Alaska House names leadership

LAND & LEASING

PIPELINES & DOWNSTREAM

Forecast of U.S. oil supremacydraws wide notice, and doubts

RCA pledges to make decisionby Dec. 14 on Koch TAPS transfer

Pushing for growth

Hilcorp increases oil production in its newly acquired Cook Inlet fields

Flint Hills drops LNG

Refiner cites improved economics, reluctanceto lead in solving energy problems

Native opposition builds

First Nations across Canada attempt to stall Northern Gateway, Kitimat, Enbridge

ON THE COVER

reach new horizons.

SIDEBAR, Page 13: Hilcorp applies for Deep Creek survey

SIDEBAR, Page 9: CEA files gas contract for GVEA supply

page11

Parnell heads governors’ 7-membercoastal states coalition E X P L O R A T I O N & P R O D U C T I O N

N A T U R A L G A S

E X P L O R A T I O N & P R O D U C T I O N

Vol. 17, No. 44 • www.PetroleumNews.comA weekly oil & gas newspaper based in Anchorage, Alaska

Week of October 28, 2012 • $2

The October issue of North of 60 Mining News is enclosed.

October Mining News inside

PHOTO BY CHRIS AREN D, COURT ES Y OF USI BELLI COA L MI NE I NC .

Thomas Tak e, ch arged w ith the large task of repairing

tires at the U sibelli Coal M ine in Healy, holds one of

some 4,500 high-paying mining jobs in Alaska. An

employment forecast published by the Alaska

Depa rtment of Labor and W or kforce Development in

October pegged the state’s mining sector job grow th

from 2010 t o 2020 at 19 percent. Page 14.

A special supplement to Petroleum NewsWEEK OFOctober 28, 2012

3 P en t a g o n ba ck s U cor e in no v a tio n

Contract ties DoD to Bokan, state-of-the-art method for extracting REEs

11 E m er a l ds g l im m e r in g o ld s e tt i n g

North C ountry Gold makes rare gem discovery in Nunavut greenstone belt

24 N e w G old t h ir s t y f or B l a ck w a te r

Miner dri lls 250,000 meters, makes vast land grab in gold-rich central BC

Budget planners cautious; landsales, well authorizations down

Bean counters and number crunchers are in full swing in

Canada assembling 2013 capital budgets against a worrying

backdrop of shaky industry forecasts, sharp declines in gov-

ernment land auctions and plunging new well permits issued

by regulators.The current betting points to troubles for the upstream,

reflected in gyrating oil and natural gas prices, and a contin-

uation of the lackluster showing in the drilling sector that has

extended over recent years.One of the early messages came from Schlumberger Chief

Executive Officer Paal Kibsgaard, who told analysts that liq-

uids activity in North America will “no longer be able to off-Hanging pipeline: September floodsleave Kenai area gas line dangling

Roads and railroad bridges weren’t the only things that

washed out in the heavy rains which hit Southcentral Alaska

in September. Marathon Oil, in the process of selling its Cook Inlet

assets to Hilcorp Alaska, is dealing with a washout along

Kalifonsky Beach Road near Kenai which left a segment of a

gas pipeline dangling. The Pipeline and Hazardous Materials Safety

Administration, PHMSA, described the situation and action it

requires in an Oct. 5 corrective action order. The affected line is a 20-inch diameter pipeline transport-

ing natural gas from the Kenai gas field to facilities south of

Kenai. PHMSA said the line was buried parallel to and with-

see BUDGET CAUTION page 18

see FLOODING AFTERMATH page 21

CD-5 is aliveConoco sanctions Alpine West; now needs partner approval; first oil by 2016

By ERIC LIDJIFor Petroleum NewsA fter years of permitting delays, ConocoPhillips

Co. is moving ahead on CD-5, the fourth satel-

lite of its Alpine field on the North Slope, the com-

pany announced Oct. 25.The ConocoPhillips board sanctioned the project

in October, Executive Vice President Exploration

and Production Matt Fox said during a third quarter

earnings call. “The project is now pending partner

approval, which is expected in November,” Fox said.

ConocoPhillips expects CD-5 production to begin

in 2016, Fox said. The company previously estimat-

ed construction would begin in 2014 with first oil in

late 2015.

After bringing the Alpine field at the Colville

River unit into production in 2000, ConocoPhillips

and its partner Anadarko brought three Alpine satel-

lites online over the following decade: Fiord in

August 2006, Nanuq in December 2006 and Qannik

in 2008. Also known as Alpine West, the CD-5 satellite

ConocoPhillips produced some 176,000barrels of oil equivalent per day in

Alaska during the third quarter, downsome 32,000 barrels of oil equivalent per

day from the same period last year.

see CD-5 page 22New field ‘challenge’ExxonMobil: Schedule is tight for achieving first production at Point Thomson

By WESLEY LOYFor Petroleum NewsM eeting the target date for starting productionfrom Alaska’s Point Thomson field will be “a

challenge,” an ExxonMobil executive said.The company has pledged to start producing natu-

ral gas condensate from the remote eastern North

Slope field by the winter of 2015-16.But it still has multiple permitting hurdles to clear

before it can begin construction of production facili-

ties and a pipeline to feed the condensate into the

existing North Slope transportation network.Company representatives appeared Oct. 23 at a

hearing of the Regulatory Commission of Alaska,

which is considering an ExxonMobil subsidiary’s

application for a certificate of public convenience and

necessity to build and operate the 22-mile pipeline.

One commissioner asked the ExxonMobil reps

whether they are on schedule with the Point Thomson

project.“We are on schedule, but it is very tight,” replied

Jeff Ray, vice president of PTE Pipeline LLC, the

company seeking the certificate for the Point

Aside from the certificate, ExxonMobilneeds a number of other major

authorizations before it can proceed withthe Point Thomson development.

see TIGHT SCHEDULE page 23Time for action is hereSouthcentral Alaska utilities are moving forward on options for gas imports

By ALAN BAILEYPetroleum NewsWith natural gas supplies from Cook Inlet set

to fall short of local gas demand by 2014 or

2015, the time has come tomove ahead with arrange-ments to supplement thoselocal supplies with importsfrom elsewhere, Southcentralpower and gas utility executives told the

Regulatory Commission of Alaska during a public

meeting on Oct. 24. Southcentral residents and

businesses depend on gas both for power genera-

tion and for the heating of buildings.“I’m personally done wringing my hands,”

Bradley Evans, CEO of Chugach Electric

Association, told the commissioners, saying he

takes responsibility for ensuring continuity of gas

supplies for his utility. Chugach Electric currently

generates about 90 percent its power using gas-

fueled power plants.

Lee Thibert, senior vice president ofChugach Electric, said that the utilities

have asked potential shippers of importedgas for expressions of interest in theimport arrangements.

see GAS IMPORTS page 24

What's the big attraction?A. an industry institutionB. quality, accurate reportingC. attractive, readable designD. 98 percent market saturation

To advertise in Petroleum News callSusan Crane at 907-770-5592, orBonnie Yonker at 425-483-9705. Tosubscribe visit PetroleumNews.com,call 907-522-9469, or email [email protected].

http://www.ukpik.com/

PETROLEUM NEWS • WEEK OF DECEMBER 2, 2012 3

Rig Owner/Rig Type Rig No. Rig Location/Activity Operator or Status

Alaska Rig StatusNorth Slope - Onshore

Doyon DrillingDreco 1250 UE 14 (SCR/TD) Prudhoe Bay E-20 workover BPDreco 1000 UE 16 (SCR/TD) Milne Point MPE-03 BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD1-01 ConocoPhillipsAC Mobile 25 Prudhoe Bay Z-10A BPOIME 2000 141 (SCR/TD) Kuparuk 3Q-06 ConocoPhillips

Kuukpik 5 Stacked in Deadhorse Linc Energy Operations Inc.Umiat Job

Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Prudhoe Bay StackedAC Coil Hybrid CDR-2 Kuparuk 3H-11 ConocoPhillips Dreco 1000 UE 2-ES Prudhoe Bay AvailableMid-Continental U36A 3-S Prudhoe Bay Available Oilwell 700 E 4-ES (SCR) Prudhoe Bay Available Dreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay Committed Dreco 1000 UE 9-ES (SCR/TD) Prudhoe Bay Available Oilwell 2000 Hercules 14-E (SCR) Prudhoe Bay AvailableOilwell 2000 Hercules 16-E (SCR/TD) Prudhoe Bay Available Oilwell 2000 17-E (SCR/TD) Prudhoe Bay Stacked Emsco Electro-hoist -2 18-E (SCR) Prudhoe Bay StackedEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Prudhoe Bay Stacked Emsco Electro-hoist 28-E (SCR) Prudhoe Bay StackedEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) Prudhoe Bay* Available Oilwell 2000 33-E Prudhoe Bay Available Academy AC electric Canrig 105-E (SCR-TD) Prudhoe Bay Commiitted

*Pioneer winter work

Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site E-20B BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay Well Drill Site W-02 BP Ideco 900 3 (SCR/TD) Kuparuk Well 3M-13 ConocoPhillips

Parker Drilling Arctic Operating Inc. NOV ADS-10SD 272 Prudhoe Bay final construction and commission BPNOV ADS-10SD 273 BP Acceptance meeting scheduled BP

for Dec. 4th, BP IAT scheduled for Jan. 8-15, 2013

North Slope - Offshore

BPTop drive, supersized Liberty rig Inactive BP

Nabors Alaska DrillingOIME 1000 19-E (AC) Oooguruk ODSN-29 Pioneer Natural ResourcesOIME 2000 245-E Oliktok Point ENI

Doyon DrillingSky Top Brewster NE-12 15 (SCR/TD) Spy Island SP30-W1 ENI

Cook Inlet Basin – Onshore

Kenai Land Ventures LLC (All American Consultants, labor Contract)Taylor Glacier 1 Kenai Loop Drilling Pad #1 Buccaneer Energy Ltd

Aurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Happy Valley drilling HV B-16 Hilcorp Alaska LLC

Cook Inlet EnergyAtlas Copco RD20 34 Finalizing Otter Project west side Cook Inlet Energy

of Beluga River Field

Doyon DrillingTSM 7000 Arctic Fox #1 Swanson River SRU 23B-22 Hilcorp Alaska LLC

Nabors Alaska Drilling99AC North Fork 23-25 Armstrong Cook Inlet LLC

Continental Emsco E3000 273E Kenai AvailableFranks 26 Kenai StackedIDECO 2100 E 429E (SCR) Stacked in Kenai Available Rigmaster 850 129 Kenai AvailableAcademy AC electric Heli-Rig 106-E (SCR/TD) Tiger Eye 1 NordAq

Cook Inlet Basin – Offshore

XTO EnergyNational 110 C (TD) Idle XTO

Spartan Drilling Baker Marine ILC-Skidoff, jack-up Spartan 151 Furie

Upper Cook Inlet KLU#1

Cook Inlet EnergyNational 1320 35 Osprey Platform RU-1, Cook Inlet Energy

workover

Hilcorp Alaska LLC (Kuukpik, labor contract)Steelhead Platform Well M-31 Hilcorp Alaska LLCredrill

428 Anna Platform, working on rig Hilcorp Alaska LLC

Mackenzie Rig StatusCanadian Beaufort Sea

SDC Drilling Inc.SSDC CANMAR Island Rig #2 SDC Set down at Roland Bay Available

Central Mackenzie Valley

Akita/SAHTUOilwell 500 51 Still out of the NWT, but is again Available

available

Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of November 29, 2012.

Active drilling companies only listed.

TD = rigs equipped with top drive units WO = workover operations CT = coiled tubing operation SCR = electric rig

This rig report was prepared by Marti Reeve

Baker Hughes North America rotary rig counts*Nov. 21 Nov. 16 Year Ago

US 1,817 1,809 2,000Canada 387 384 484Gulf 50 48 38

Highest/LowestUS/Highest 4530 December 1981US/Lowest 488 April 1999Canada/Highest 558 January 2000Canada/Lowest 29 April 1992

*Issued by Baker Hughes since 1944

The Alaska - Mackenzie Rig Report is sponsored by:

JUDY

PAT

RICK

� G O V E R N M E N T

U.S. suspends BPfederal contractingEPA cites company’s criminal prosecution for Deepwater Horizonas basis for action; BP stresses suspension is temporary, limited


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GOVERNMENTAlaska House names leadership

The Alaska House majority and minority have organized for the upcoming 28thLegislature.

The largely Republican majority has named Rep. Mike Chenault, R-Nikiski, toa third term as speaker. Rep. Lance Pruitt, R-Anchorage, is the new majorityleader and Rep. Craig Johnson, R-Anchorage, returns as Rules chair.

The House Finance Committee will be co-chaired by Reps. Bill Stoltze, R-Mat-Su/Chugiak and Alan Austerman, R-Kodiak.

Rep. Peggy Wilson, R-Wrangell, returns for a second term as majority whip. In addition to Stoltze and Austerman, House Finance majority members are:

Reps. Mark Neuman, R-Big Lake; Bryce Edgmon, D-Dillingham; Cathy Munoz,R-Juneau; Tammie Wilson, R-North Pole, Mia Costello, R-Anchorage; and SteveThompson, R-Fairbanks.

Chairs of resource-related committees include: Reps. Eric Feige, R-Chickaloonand Dan Saddler, R-JBER/Eagle River, co-chairs of House Resources; and Reps.

By WESLEY LOYFor Petroleum News

In yet more fallout from the DeepwaterHorizon disaster, London-based BP has

lost its ability to sign new contracts with theU.S. government.

Such contracts can range from oil andgas leases to fuel sales to the U.S. military, asignificant business for BP.

The U.S. Environmental ProtectionAgency announced the action against BP onNov. 28.

“EPA is taking this action due to BP’slack of business integrity as demonstratedby the company’s conduct with regard to theDeepwater Horizon blowout, explosion, oilspill, and response,” the EPA said.

Under a plea agreement announced Nov.15, BP has agreed to plead guilty to 11counts of felony manslaughter and othercharges in connection with the fieryblowout on April 20, 2010, aboard thedrilling rig Deepwater Horizon offshoreLouisiana. BP has agreed to pay $4 billionin fines and other penalties.

Also, three current or former BPemployees face criminal charges in connec-tion with the disaster.

The federal government is now pursuingpotentially huge civil claims against BP.

Suspension is ‘standard practice’“For the Deepwater Horizon investiga-

tion, EPA was designated as the lead agencyfor suspension and debarment actions,” theEPA said. “Federal executive branch agen-cies take these actions to ensure the integri-ty of federal programs by conducting busi-ness only with responsible individuals orcompanies. Suspensions are a standardpractice when a responsibility question israised by action in a criminal case.”

The EPA added: “The BP suspensionwill temporarily prevent the company andthe named affiliates from getting new feder-al government contracts, grants or othercovered transactions until the company canprovide sufficient evidence to EPA demon-strating that it meets federal business stan-dards. The suspension does not affect exist-ing agreements BP may have with the gov-ernment.”

The EPA provided Petroleum News with

a copy of the “notice of suspensions” givento BP. Among the numerous subsidiariesand affiliates listed in the notice is BPExploration (Alaska) Inc.

The eight-page notice says BP’s “seri-ously improper conduct provides the basisfor its suspension” from federal contracting.

BP and its subsidiaries have been pub-lished in the System for AwardManagement, or SAM, as “ineligible” toreceive any federal contract, the notice says.The General Services Administration main-tains the SAM website.

BP companies also are “precluded fromreceiving certain federal assistance, loansand benefits,” the notice says.

The notice adds: “It is important to notethat suspension is not imposed for the pur-pose of punishment. It is a discretionarymeasure used to insure that the Governmentconducts public business with responsiblepersons.”

Existing contracts remain validBP, in a Nov. 28 press release, said the

EPA action “relates only to future potentialcontracts with the U.S. government. Thetemporary suspension does not affect anyexisting contracts the company has with theU.S. government, including those relating tocurrent and ongoing drilling and productionoperations in the Gulf of Mexico.”

BP continued:“The EPA’s action is pursuant to admin-

istrative procedures providing for discre-tionary suspension until a company candemonstrate ‘present responsibility’ to con-duct business with the U.S. government. BPhas been in regular dialogue with the EPAand has already provided both a presentresponsibility statement of more than 100pages and supplemental answers to theEPA’s questions based on that submission.

“Moreover, in support of BP’s efforts toestablish present responsibility, the U.S.Department of Justice agreed, in the pleaagreement, that it will advise any appropri-ate suspension or debarment authority thatin the Department’s view, BP has acceptedcriminal responsibility for its conduct relat-ing to the Deepwater Horizon blowout,explosion, oil spill and response. The EPAhas informed BP that it is preparing a pro-

see HOUSE LEADERSHIP page 5

see BP CONTRACTING page 11

http://www.nascoinc.com/

By KRISTEN NELSONPetroleum News

A lyeska Pipeline Service Co. has lostan appeal of the Department of

Natural Resources’ 2002 appraisal of thevalue of trans-Alaska pipeline systemleases at $236,000 per year.

In a Nov. 23 ruling the AlaskaSupreme Court affirmed a decision by theAlaska Superior Court upholding DNR’sappraisal of the TAPS lease price.

Alyeska had appealed to the AlaskaSupreme Court, arguing that DNR misin-terpreted state statute on calculation ofthe lease price; that DNR was required toadopt its interpretation of statute as a reg-ulation; and that the appraisal improperlyincluded submerged lands within theright-of-way.

Under Alaska’s Right-of-Way LeasingAct DNR is required to adjust the leaseprice for the TAPS right of way every fiveyears, the court said. In 2002, DNR andthe U.S. Bureau of Land Managementhired Black-Smith & Richards Inc. toappraise state and federal lands within theright of way. Black-Smith was instructedto appraise the right of way based on thefair market value of the land. DNR noti-fied Alyeska in December 2002 that ithad approved the Black-Smith appraisaland that the annual rent for state landswithin the right of way would be$236,000 per year.

Second appraisalAlyeska had a review of the Black-

Smith appraisal done by real estateappraiser Al Olson and Olson’s reviewfound potential issues, two of which thecourt said were relevant.

Olson said the appraisal’s valuation ofstate lands at 100 percent did not accountfor the fact that under its leases Alyeskadid not have exclusive use of the land andspeculated that if Black-Smith had beenallowed to consider the non-exclusive useit might have valued the land at 75 per-cent fee value, which Olson referred to asthe encumbrance of rights issue.

Olson also noted that the appraisalincluded 205.78 acres of submerged landswhich were disputed acreage in navigablewaterways, but the appraisal did not valuethe lands as such, referred to as the sub-merged lands issue.

Alyeska appealsAlyeska appealed DNR’s appraisal to

the commissioner, raising the encum-brance of rights issue and the submergedlands issue and requesting that the

appraisal be reexamined and revised onthose grounds.

The commissioner affirmed DNR’sdecision in September 2006, rejecting theencumbrance of rights argument and rul-ing that the state Right-of-Way LeasingAct required that the lease price be basedon the fair value of land without reduc-tion for rights retained by the state orgranted to third parties, but refused toaddress the submerged lands issue, stat-ing that there was an agreement withAlyeska not to address that issue.

Alyeska appealed to the AlaskaSuperior Court, disputing assessment at100 percent of value even thoughAlyeska’s leasehold rights were not exclu-sive and disputing an oral agreement onthe submerged lands issue. Alyeska askedthe court to remand to the commissioneron the submerged lands issue, which thecourt did.

In April 2008 the commissioneraffirmed the appraised valuation of sub-merged lands along the right of way.

In August 2010 the Superior Courtaffirmed the commissioner’s final ruling.

Alyeska appealed to the AlaskaSupreme Court, arguing that valuationshould include consideration of the non-exclusive nature of the leasehold interest.Alyeska argued that even if DNR correct-ly interpreted the Right-of-Way LeasingAct, DNR was required to adopt its inter-pretation as a regulation. Alyeska alsoargued DNR’s appraisal improperlyincluded submerged lands when it hadfailed to establish the state held title tothose lands.

No regulation requiredThe court found that DNR’s interpreta-

tion of the Right-of-Way Leasing Act wasreasonable, and it was not required toadopt a regulation.

The court said the act “broadly defines‘state land’ as ‘any interest owned by thestate in land if the interest is sufficient topermit the state to lease it” under the act,which refers to the definition of state landunder the Alaska Land Act, which“defines ‘state land’ as ‘all land, includ-ing shore, tide, and submerged land, or

resources belonging to or acquired by thestate.’”

Rights not exclusiveThe court said that when the commis-

sioner rejected Alyeska’s argument that itshould not pay 100 percent of the valuefor non-exclusive rights, the commission-er reasoned that the law required the leaseprice to be based on fair market value ofstate right-of-way land, defined as anyinterest owned by the state, “not just theinterest granted to Alyeska via the right-of-way agreement,” and did not require areduction for rights retained by the stateor granted to third parties “where, as here,those interests did not reduce the value ofthe land.” The commissioner notedAlyeska’s use of the right of way was pro-tected by law from incompatible uses andsaid that as of the date of the appraisal“none of the third-party interests withinthe TAPS right-of-way interfere with theTAPS right-of-way grant.”

The court said Alyeska challenged theruling on several grounds.

The court said it found DNR’s inter-pretation of statute for the method of cal-culating right-of-way prices was reason-able, and said it “is consistent with theplain language of the statute and thestatutory definitions of ‘state land’,”including the broad definition in theRight-of-Way-Leasing Act of state landas all land and any interest in land ownedby the state.

The court said, “Although Alyeskafocuses on the fair market value of theleasehold interest, the correct analysisfocuses on the fair market value of thestate land.” The court also said it agreedthat if there were to be third-party usesthat reduced the value of the land, “asopposed to the value of the lease,” thenthe value would take those third-partyinterests into account.

The court also found DNR’s “conclu-sion that the plain language of the statuterequires the lease price to be based on thefair market value of the state land withinthe right-of-way, rather than the fair mar-ket value of the leasehold interest, is rea-sonable.”

The court also said DNR was notrequired to adopt a regulation because itsinterpretation did “not add substantiverequirements to the statute” but simplyinterpreted the statute according to itsown terms.

Constitutional argumentThe court said Alyeska also argued that

DNR’s interpretation of statute “unlawfullyburdens interstate commerce in violation ofarticle I, section 8 of the federal constitu-tion because it results in a lease price thatexceeds ‘fair compensation’ for a non-exclusive lease such as the TAPS lease.”

But, the court said, Alyeska did not raisethis issue in its appeal to the commissioneror in its appeal to the Superior Court, “butraised the issue for the first time in its replybrief before the superior court. Alyeskaalso offers little argument or authority sup-porting its argument, relying exclusively ona single paragraph quoted from a 1973 trialcourt brief.” The court said it agrees withDNR that Alyeska waived this argumentbecause it did not raise the issue in itsappeal to the commissioner or on appeal tothe superior court, and “has abandoned theissue by briefing it in such a cursory fash-ion.”

The court also ruled that DNR was notrequired to prove the state held title to sub-merged lands within the right of way.

It said that while Alyeska argued it wasrequired to pay rent to both the state and thefederal government, it “failed to demon-strate that it was actually required to payrent to both the state and federal govern-ments for the same submerged lands with-in the TAPS right-of-way.”

The court said that on appeal Alyeskarelied exclusively on its appraiser’s state-ment that the Black-Smith appraisalincluded lands which were reported to bedisputed acreage in navigable waterways.But the court said the appraiser’s statement“is essentially hearsay” and does not estab-lish that Alyeska was required to pay rentto both governments for the same sub-merged lands within the right of way. �

� P I P E L I N E S & D O W N S T R E A M

Alyeska loses to state on ROW valuationAlaska Supreme Court affirms Superior Court on DNR 2002 appraisal of value of trans-Alaska oil pipeline state right-of-way leases


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Charisse Millett, R-Anchorage, andDoug Isaacson, R-North Pole, co-chairsEnergy.

On the minority side, Rep. BethKerttula, D-Juneau, returns as HouseDemocratic leader; Rep. Chris Tuck, D-Anchorage, will be the HouseDemocratic whip; and Rep. MaxGruenberg, D-Anchorage, remainsHouse Democratic floor leader.

House Democratic caucus assign-ments to House Finance are Reps. LesGara, D-Anchorage; David Guttenberg,D-Fairbanks; and Scott Kawasaki, D-Fairbanks.

—PETROLEUM NEWS

continued from page 4

HOUSE LEADERSHIP

Contact Kristen Nelson at [email protected]

http://www.astac.net


A lthough there has been much recentfocus on the risks associated with

exploratory oil drilling in the Arctic off-shore, it is necessary to take a broaderview of arctic oil spill contingency plan-ning, addressing for example risks associ-ated with general arctic shipping andlooking at risk management for the futuredevelopment and production of oilresources, Mark Myers, vice chancellor ofresearch at the University of AlaskaFairbanks, or UAF, told a meeting of theAlaska Geological Society on Nov. 28.Myers has been promoting the establish-ment of an oil spill research center at theuniversity.

“It’s a very different world when you’redoing summer exploration only and in ice-free conditions than when you’re on pro-duction in the further offshore,” Myers

said. But there istime to work on theissues, with emerg-ing technologiesoffering opportuni-ties for solving prob-lems, he said.

Dynamic changeThe shrinking sea

ice cover in theArctic is leading to dynamic change inhuman activity, including increased ship-ping, more tourism and a burgeoninginterest in offshore arctic mineralresources, Myers said. In the oil and gasindustry new technologies such as subseawell completions are enabling betteraccess to major offshore resources, whilehigh oil prices are driving an interest inseeking these resources. Ships plying theArctic carry oil as fuel.

“There’s a significant shipping risk as

shipping increases, let alone the oil trafficthat is seasonally now travelling betweenthe east coast of Russia and markets in theFar East,” Myers said. “The risk is not justlimited to oil and gas.”

Internationally, oil and gas explorationin the Arctic is taking place in a relativelyclosed basin, where an oil spill in oneplace can impact countries beyond thespill location.

“So the reality is, no matter what U.S.policy is … the United States will facerisks for oil spills,” Myers said.

Infrastructure and researchBut, while there is much concern about

environmental risk, a general lack of sup-port infrastructure in the Arctic presents amajor challenge to operations in theregion. The U.S. Coast Guard is very con-cerned about its capacity to operate in theArctic. Helicopters, for example, tend notwork to well in cold weather. And com-

munications systems are poor in the Arcticoffshore, Myers said.

Follow-up studies in the aftermath ofthe Deepwater Horizon disaster havepointed to the need for research and foradditional government and industryresponse capacities in the Arctic offshore,he said.

There is also a need for a better under-standing of the complex interdependenceof different offshore ecosystems, withcontinuing environmental change addingto the difficulty of environmental regula-tion, he said. And site-specific, geology-based analysis of oil spill risks matterswhen it comes to spill response planning.

Fundamental questions about topicssuch as the movement and behavior of oilin ice-laden waters; the locations of criti-cal habitats that need protection; and thetolerance of the food web to oil or disper-sants are starting to be answered but stillrequire much research.

The human factor — how people per-ceive and respond to the risks — is alsocritical, Myers said.

UAF centerMyers hopes to establish the UAF oil

spill response center in 2013 to seek inno-vative approaches to addressing arctic oilspill response challenges. Last year theNational Science Foundation decided thatit would not fund the initiative, becausethe foundation viewed an oil spill researchinstitute as an inappropriate target for itsfunding, Myers said. Instead, the universi-ty is now hoping for some state funding tobuild the coordination component of the


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Myers argues for UAF oil spill researchSays that oil development and other Arctic offshore activities will drive a need for innovative spill response technologies

MARK MYERS

see UAF RESEARCH page 7

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proposed center — the research compo-nents of the center already exist in variousuniversity research departments, Myerssaid.

“Can we take new, emerging technolo-gies and different approaches, can we inte-grate approaches, to come up with … inte-grated (response) capacity in Alaska?”Myers asked, commenting that doingresearch in Alaska would provide anopportunity to build an Alaska-basedindustry around that research. It might, forexample, be possible to build a tank fortesting spill response equipment in Arcticconditions.

The university could potentially

become a bridge between industry and thegovernment, to facilitate the developmentof spill response capacity. The centerwould also communicate with Alaskacommunities through its existing networkof rural campuses and research relation-ships, Myers said.

“We certainly are very interested ingetting industry or (government) agencypartnerships as we move forward with theconcept,” Myers said.

Leverage knowledgeWhile avoiding the re-invention of

wheels being worked on by others —research into the mechanical recovery orin-situ burning of spilled oil, for example— the university could leverage its arcticknowledge, building on its existingexpertise to become a center for the trans-

fer of arctic oil spill response knowledge,Myers said. And Myers cited the recentlaunch of UAF’s ice-capable research ves-sel, the Sikuliaq, as an example of the typeof arctic research technology that the uni-versity could bring to the oil spill researchtable.

The university has been working onunmanned underwater vehicles that arecapable of operating under the sea ice forlong-term subsea observations. The uni-versity has also for a long time beenresearching unmanned aerial vehicle tech-nology, something that could become anenabling technology for, for example,extended offshore operations, includingoperations in poor visibility using infraredand other sensors.

“What we envision … is taking someof the emerging technologies to approach

some of the most difficult problems,”Myers said.

Water circulation in the Arctic Oceanand the movements of ocean currentsunder the ice are not well understood andthere is potential for developing improvedoil spill trajectory models in ice condi-tions, he said. The university has world-class skills in climate modeling and inmodeling the movement of sea ice, Myerssaid.

“A lot of fundamental new researchopportunities are up here and the ability toincorporate that into the operational struc-ture I think would dramatically improveconfidence in the ability to respond to anoil spill in the Arctic,” Myers said. �


UAF RESEARCH

Contact Alan Bailey at [email protected]

� L A N D & L E A S I N G

Cook Inlet Energy requests lease expansionCompany wants acreage added to Mental Health Trust lease on west side near Tyonek, proposes drilling 2 wells over next 2 years

By ERIC LIDJIFor Petroleum News

Cook Inlet Energy plans to drill two wells on the westside of Cook Inlet by the end of 2013 in exchange for

the Alaska Mental Health Trust expanding a lease in the area.The independent is asking the Trust Land Office to add

some 1,660 acres to lease MHT 9300063, on “highlyprospective” land around 10 miles north of the village ofTyonek.

The proposed expansion area covers a portion of twotracts. The Division of Oil and Gas originally leased theacreage as ADL 391126 before conveying it to the Trust.

Apache Corp. held the lease until it expired at the end ofSeptember. Cook Inlet Energy holds state and Mental HealthTrust leases on either side of the proposed expansion. TheMHT 9300063 lease is scheduled to reach the end of its pri-

mary term on Dec. 30, as is another Trust lease, MHT9300062, on the other side of the expansion acreage. Thestate leases Cook Inlet Energy holds in the area are sched-uled to expire in February 2018.

No previous developmentThere has not been any previous development on the

acreage, according to the Trust, but the acreage is just westof the Beluga River and the Pretty Creek units and just northof the Lone Creek and the former Three Mile Creek units.Some exploration in the vicinity includes a recent LincEnergy Inc. stratigraphic test for deep coal deposits, the N.Beluga No. 1 well that Pelican Hill drilled in late 2004 (find-ing “a reservoir, but no gas,” Arlen Ehm told PetroleumNews at the time) and the Burglin X33-12 well from 1976-1977.

Under its proposal, Cook Inlet Energy would lease the

additional acreage through the end of 2013 for $3 per acreper year, a bonus payment of $25,730 and 12.5 percent roy-alty.

In return for the expansion, the company has committedto drill an exploration well on one lease by the end of 2012and a second exploration well on the other lease by the endof 2013. Cook Inlet Energy would lose one of the two leas-es if it failed to drill the first well and would pay the Trust a$250,000 penalty if it failed to drill the second well.

The Trust is taking comments on the proposal throughDec. 20.�

—A copyrighted oil and gas lease map fromMapmakers Alaska was a research tool used in preparingthis story.

Contact Eric Lidji at [email protected]

http://www.asrcenergy.com/


Thanks to what is termed “combinedcycle” technology, Alaska’s

Southcentral Power Project, a new gas-fired power generation facility undergoingcommissioning tests in midtownAnchorage, will use just 70 to 75 percent ofnatural gas fuel per unit of generated elec-trical power compared with the region’saging gas-fired power stations, power utili-ty executives told the Anchorage Chamberof Commerce Make it Monday Forum onNov. 26. But with the $369 million plantthat is being constructed by ChugachElectric Association and Municipal Light& Power scheduled to come on line in thefirst quarter of 2013, electricity consumerscan expect to see increases in their electric-ity bills, to cover the construction costs.

Phil Steyer, director of government rela-tions and corporate communications for

Chugach Electric, likened the situation tothe purchase of a new fuel-efficient car,with the necessity of an up-front purchasecost in the interests of long-term fuel sav-ings.

“Initially I expect that will cause yourbills to go up,” Steyer said. “Over the longterm, because we’re going to use less gas, Iexpect that to be a net savings.”

Rate increaseSteyer said that Chugach Electric will

also need to increase its rates a bit tocover the cost of responding to a severewind and rain storm that hit theAnchorage bowl in September. Overall,consumers may expect to see a 5 to 10percent increase in their electricity bills in2013, Steyer said. However, thanks toimproved energy efficiency, consumersare also tending to use less electricitythan in the past — on average, a con-sumer’s usage has dropped from 700 kilo-watt-hours per month to 650 kilowatt-hours per month, Steyer said.

Steyer also commented that ChugachElectric’s gas costs for 2013 are uncertainat the moment — the utility passes thesecosts through to its customers as a com-ponent of their electricity bills. This is thefirst winter in which the utility will haveto withdraw gas that it has warehoused ina new gas storage facility operated on theKenai Peninsula by Cook Inlet NaturalGas Storage Alaska, known as CINGSA

— the stored gas is needed because theutility’s gas suppliers, Marathon andConocoPhillips, can no longer meet allChugach Electric’s power generation fuelneeds during periods of high winterdemand, Steyer said.

ML&P: busy yearJim Posey, general manager of

Municipal Light & Power, or ML&P,characterized 2012 as having been hisutility’s busiest construction season in atleast 30 years. In addition to a series ofconstruction projects aimed at addressingvarious customers’ needs, ML&P had tocontend with the aftermath of theSeptember storm.

The utility is forging ahead with plansto upgrade its aging facilities, includingits share of the Southcentral PowerProject and the construction of a new,efficient gas-fired power plant in itspower station north of downtownAnchorage. The turbines for ML&P’snew plant will arrive in 2014 for installa-tion in 2015, Posey said. ML&P has beenpreparing the site for the plant, he said.

ML&P is also constructing two newsubstations in midtown Anchorage toconnect with the Southcentral PowerProject when that facility comes online.

As with Chugach Electric, ML&P hascontracted with CINGSA for the storageof gas for use during the winter. The util-ity has also contracted withConocoPhillips for the delivery of addi-tional gas at the rate of 5 million to 6 mil-lion cubic feet per day during the winter,with an expectation that this gas will beneeded on a few occasions, Posey said.

Beluga fieldML&P is a co-owner of the Beluga gas

field, on the west side of the Cook Inlet,and the utility obtains much of its gasfrom that field. In addition to maintaininggas compression facilities, the partners inthe field have recently spent $60 milliondrilling three new gas wells. Two of thosewells proved successful, but one well pro-duced water rather than gas, Posey said.

All told, ML&P anticipates spendingsome $459 million between 2012 and2017 on its new power plant; transmissionand distribution upgrades; general plantwork; and projects in the Beluga field,Posey said. That expenditure will requirean electricity rate increase before the endof this year, he said, adding that ML&Panticipates another rate increase after theSouthcentral Power Project comes onlineand the final costs of that project areknown.

MEAJoe Griffith, general manager of

Matanuska Electric Association, or MEA,talked about the Eklutna GenerationStation, or EGS, the new, modern gas-fired power station that his utility isbuilding north of Anchorage. MEA cur-rently purchases power from ChugachElectric: When the EGS facility comes online in 2015 this facility will displacesome of Chugach Electric’s generationcapacity.

MEA has already cleared the site andpurchased the massive engines for the170 megawatt EGS project, a project thathas an estimated price tag of $265 mil-lion, Griffith said. The utility has upgrad-ed its computer control system for its

� U T I L I T I E S

Utilities improve efficiency at a costNew Southcentral Alaska power generation will reduce long-term fuel needs while triggering price increases in the near future


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Better.

Phil Steyer, director of governmentrelations and corporate

communications for ChugachElectric, likened the situation to

the purchase of a new fuel-efficient car, with the necessity ofan up-front purchase cost in the

interests of long-term fuel savings.

see UTILITY EFFICIENCY page 9

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Gas declineSteyer said that the utilities’ new, high-

ly efficient power plants form one com-ponent of a series of measures addressingthe continuing decline in production fromCook Inlet’s aging gas fields. Other meas-ures taken in response to the gas supplysituation include the successful construc-tion of the CINGSA gas storage facilityand the instigation of bidirectional gasflow through the Cook Inlet GasGathering System, a major gas pipelineunder Cook Inlet. Energy efficiency andconservation are reducing gas demand,while Chugach Electric is now obtainingsome power from a new wind farm onFire Island, offshore Anchorage. A project

is under way for the eventual constructionof a major hydropower system at Watanaon the Susitna River.

And state exploration and productionincentives have encouraged much new oiland gas exploration in the Cook Inletbasin.

The utilities are moving ahead with aplan to import either liquefied or com-pressed natural gas into the region, to filla projected gas supply shortfall starting inthe winter of 2014-15. And there is an“Energy Watch” program in place duringthe winter, to alert Southcentral residentsof any need to reduce energy usage,should a gas shortage occur.

So far the utilities have succeeded inworking with each other and the gas pro-ducers to ensure the continuity of gassupplies when winter demand has peaked,Steyer said. A request to the public forvoluntary cuts in energy use under theEnergy Watch program would be an indi-cation that the utilities have run out ofoptions to stave off a gas shortfall — inthis situation it is important that peoplerespond, to avoid a need for power cuts,Steyer cautioned. �

CEA files gas contract for GVEA supplyChugach Electric Association has asked the Regulatory Commission of Alaska

to approve a new gas supply contract with Hilcorp Alaska, for gas for power gen-eration for the supply of electricity to Fairbanks utility Golden Valley ElectricAssociation, or GVEA. GVEA purchases some of its power from ChugachElectric to reduce its needs for expensive oil-fueled power generation inFairbanks.

The new gas supply contract covers the period April 1, 2013, to Oct. 31, 2015,and has gas prices starting at $7.75 per thousand cubic feet, rising to $7.90 onNov. 1, 2013, and stepping up to $8.06 on Nov. 1, 2014.

Although this new contract provides Chugach Electric with some assuranceabout the source of gas for its future sales of power to GVEA, the contract doesnot resolve concerns about tightening gas supplies from the Cook Inlet basin —Southcentral gas and power utilities are making plans to import gas into the regionin the winter of 2014-15, to guard against the possibility of local gas supplies run-ning short during periods of high winter demand.

Lee Thibert, senior vice president of Chugach Electric Association, toldPetroleum News Nov. 28 that Chugach Electric works with GVEA as part of theAlaska Railbelt.

“We feel they’re part of the team,” Thibert said.Chugach Electric plans to purchase gas under the new contract during the sum-

mer, placing gas in storage on the Kenai Peninsula for winter use and not impact-ing winter gas deliverability, Thibert said. And the power supply contract withGVEA is not guaranteed: In the event of a gas shortage in Southcentral AlaskaChugach Electric has the option to curtail the GVEA supply, he said.

Chugach Electric says that, as well as enabling GVEA to reduce the price ofelectricity for its customers, the revenue generated from the power supplies toGVEA will benefit Chugach Electric’s customers in Southcentral Alaska byreducing Chugach Electric’s electricity rates.

If Chugach Electric were forced to curtail its supply to GVEA, GVEA wouldpresumably have to revert to more expensive power generation in Fairbanks.

—ALAN BAILEY


UTILITY EFFICIENCY


EXPLORATION & PRODUCTIONBuccaneer permitting Cosmo wells

Buccaneer Alaska Operations LLC wants to amend its Cook Inlet oil dischargeprevention and contingency plan to include a pair of wells at the Cosmopolitanprospect.

The proposal would amend its currently approved plan for the offshoreNorthwest and Southern Cross prospects to include the Cosmopolitan No. 1 andNo. 2 exploration wells.

Under the proposed amendment, Buccaneer would begin winter operations insouthern Cook Inlet when ice conditions are less than 10 percent and would endoperations when ice conditions exceed 10 percent between November and April.

In the amendment, Buccaneer is also proposing a response planning standardof 800 barrels per day for 15 days to total 12,000 barrels for the Cosmopolitanwells.

The state is taking comments on the proposal through Dec. 28.Buccaneer would drill the wells using its Endeavour jack-up rig. According to

the Homer Tribune, the company expects the rig to remain in Homer through atleast early December while it waits for additional permits for its Cosmopolitanexploration program.

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LNG pipeline may dodge review By GARY PARK

For Petroleum News

Environmentalists in British Columbia are gearing for aregulatory and political showdown over plans by

TransCanada to build a C$4 billion natural gas pipeline tofeed the Shell Canada-operated LNG Canada project.

Under proposed changes to federal legislation, there isno assurance the proposed 420-mile, large diameterpipeline would face an environmental review — a prospectthat is arousing green leaders in the province.

Otto Langer, a former head of habitat assessment for theFisheries Department in British Columbia and the Yukon,said chances of the Coastal GasLink pipeline sidesteppingan assessment would be a “travesty of the public trust.”

Craig Orr, executive director of Watershed Watch, toldthe Vancouver Sun he was “astounded that there is even athought of exempting something of such magnitude, withsuch potential risk.”

“There is so much discretionary power now in whetheranything gets an environmental assessment. I don’t think itserves Canadians well, especially those concerned aboutthe environment.”

Federal oversight reducedUnder legislation passed by Parliament in June, the

Canadian government has reduced federal oversight of fishhabitat, transferring greater responsibility for assessment tothe provinces to avoid duplication and allow greater federalfocus on major projects.

Legislation introduced in October has been criticized forfurther eroding environmental protection, including theexemption of energy pipelines from the Navigable WatersProtection Act, limiting coverage to only three oceans, 97lakes and 62 rivers, or less than 1 percent of Canada’s water-ways.

A coalition of groups, including the British ColumbiaAssembly of First Nations, David Suzuki Foundation andEcojustice has urged that the bill not be passed.

The federal government has reportedly washed its handsof environmental assessments of 492 wide-ranging projectsin British Columbia.

Coastal GasLinkCoastal GasLink was chosen by the LNG Partners —

Shell, Korea Gas, Mitsubishi and PetroChina — and is

planned to initially carry 1.7 billion cubic feet per day of gasfrom the Montney region in northeastern British Columbia,with potential to expand to 4 bcf per day. Construction isscheduled to start in 2015, with completion due in 2018.

The Canadian Environmental Assessment Agency has adeadline of Jan. 3 to announce whether a review will be con-ducted.

A spokeswoman for the agency said that even if thatoption is eliminated “all applicable federal legislative, regu-latory and constitutional requirements must be fulfilled.”

TransCanada documents show the pipeline would cross320 watercourses, including the habitat of more than 100species at risk, such as white sturgeon and woodland cari-bou.

TransCanada has also submitted the project description tothe British Columbia government in advance of an officialassessment by the B.C. Environmental Assessment Office— a prospect Langer scoffs at, telling the Vancouver Sun theprovince is “giving the green light everywhere” to projects,adding that its review process is too soft on industry. �

Contact Gary Park through [email protected]

ENVIRONMENT & SAFETY

First Nations loseoil sands case

Two aboriginal groups in Albertahave been denied the right to make aconstitutional challenge of RoyalDutch Shell’s proposed C$12 billionexpansion of its Jackpine oil sandsmine and a new mine, arguing thatneither the company nor the Albertagovernment had properly consultedor accommodated treaty rights.

The Alberta Court of Appealrejected a bid by the AthabascaChipewyan First Nation and theMetis Nation of Alberta that wouldhave delayed work on increasing out-put from the existing mine to300,000 barrels per day from100,000 bpd in 2017 and add anoth-er 200,000 bpd from the Pierre Rivermine in 2018.

Shell filed applications for bothprojects in 2007, but the hearing hasbeen delayed until now because ofCanada’s drawn out regulatoryprocess.

Justice Frans Slattery agreed withan earlier ruling by a review panelconvened to hear arguments aboutthe project that the aboriginal nation-s’ request to stall work was beyondits jurisdiction.

Slattery said that since the FirstNations were given an opportunity toraise their objections to Shell’s proj-ect with the panel they could notissue a constitutional challenge.

Frustration with verdictAthabasca Chipewyan Chief

Allan Adam said his community was“pretty much frustrated” with theverdict.

“We anticipated the court wouldhear our arguments. The fact remainsthat there was a breach of protocoland the judge should have taken thatinto account,” he said.

“A project of this magnitudecouldn’t possibly be in the publicinterest if our rights have not beenupheld and we have not been ade-quately consulted. I don’t think thejudge understands aboriginal law.”

see SANDS CASE page 11

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GOVERNMENTItta named to Arctic Research Commission

President Obama has appointed prominent Barrow resident Edward Itta to theU.S. Arctic Research Commission, the federal agency that provides the presidentwith reports and advice on arctic research. Itta, a member and past commissioner ofthe Alaska Eskimo Whaling Commission, was mayor of the North Slope Boroughbetween 2005 and 2011, during which time he was at the cen-ter of negotiations between Shell and North Slope communitiesover Shell’s plans for Arctic outer continental shelf exploration.

Fran Ulmer, the current chair of the Arctic ResearchCommission, lauded the appointment.

“Edward Itta is a respected leader who knows the Arcticthrough a lifetime of first-hand experience,” she said.

And Alaska’s two U.S. senators expressed their support forthe president’s choice of commission member.

“As mayor of the North Slope Borough, Edward demon-strated his ability to bring people together from all sectors ofgovernment, business and science to reap benefits — and I know he will continue todo so on a national scale for the USARC,” said Sen. Lisa Murkowski. “SelectingMayor Itta is an excellent choice for a prominent position that grows more importantwith every passing month.”

Sen. Mark Begich said that he had recommended Itta to the White House.“Edward Itta has been an excellent leader and voice for Native communities,

always advocating for economic development while protecting subsistence,” Begichsaid. “His impressive resume of service to the North Slope Borough and his workwith the whaling community will allow him to offer great insight to the commission.As the Arctic grows as a focus of resource development and research activity, Mr. Ittawill be a critical voice for residents of the Arctic.”

The president has also appointed James McCarthy, a scientist specializing inmarine systems and climate, to the commission.

—ALAN BAILEY

EDWARD ITTA

During hearings over the past month,the First Nations said the developmentwould adversely affect their rights tohunt, fish and trap.

The Athabasca Chipewyan communityhas previously challenged the oil sandsapproval process, but failed eitherbecause it filed its legal action long afterthe approval process had ended, or did nothave the resources to carry a challenge toconclusion.

Shell has defended its efforts to con-

sult with First Nations over the past 15years.

Also making their case before the jointreview panel of the CanadianEnvironmental Assessment Agency andthe Alberta Energy ResourcesConservation Board have been environ-mentalists and individual citizens, includ-ing the Oil Sands EnvironmentalCoalition, an umbrella organization ofthree groups.

—GARY PARK


SANDS CASE


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posed administrative agreement that, ifagreed upon, would effectively resolve andlift this temporary suspension. The EPAnotified BP that such a draft agreementwould be available soon.”

BP said it has made “significantenhancements” since the DeepwaterHorizon accident. It has been implementingrecommendations from an internal investi-gation, and has made key leadershipchanges and reorganized its upstream busi-ness. The company also has created a cen-tralized safety and operational risk organi-zation.

“In the two and a half years since theDeepwater Horizon accident, the U.S. gov-ernment has granted BP more than 50 newleases in the Gulf of Mexico, where thecompany has been drilling safely since thegovernment moratorium was lifted,” BPsaid. “BP is the largest investor and deep-water leaseholder in the Gulf of Mexicowith more than 700 gross blocks and sevenrigs currently conducting drilling opera-tions.”

The company added that it has investedmore in the United States than any other oiland gas company over the past five years.And BP noted it has spent billions to cleanup the Gulf spill and to pay claims. �


BP CONTRACTING

Contact Wesley Loy at [email protected]

FINANCE & ECONOMYBP advances planned sale of TNK-BP stake

BP announced Nov. 22 it had signed “definitive and binding sale and purchaseagreements” for its 50 percent stake in the Russian oil and gas company TNK-BP.

The buyer is the state-owned Russian oil giant Rosneft.BP will sell its interest in TNK-BP to Rosneft for $17.1 billion in cash plus

shares representing a 12.84 percent stake in Rosneft. BP will then use $4.8 billionof the cash proceeds to buy an additional 5.66 percent stake in Rosneft from theRussian government.

“On completion, the net result of the overall transaction will be that BP willreceive $12.3 billion in cash and acquire an 18.5 percent stake in Rosneft for itsstake in TNK-BP,” BP said in a press release. “When combined with BP’s current1.25 percent shareholding, this will result in BP owning 19.75 percent ofRosneft.”

BP added: “Completion of the transaction is subject to certain customary clos-ing conditions, including governmental, regulatory and antitrust approvals. Thetwo companies still anticipate completion in the first half of 2013.”

BP will have two seats on Rosneft’s nine-person main board.Moscow-based TNK-BP was formed in 2003 as a result of the merger of BP’s

Russian oil and gas assets and the oil and gas assets of AAR, a consortium ofRussian investors Alfa Group, Access Industries and Renova.

TNK-BP is the third-largest oil producer in Russia, with a diversified upstreamand downstream portfolio in Russia and Ukraine. TNK-BP’s average daily pro-duction in 2011 was 1.987 million barrels of oil equivalent per day, BP said.

Rosneft, a fully integrated national oil and gas company, produced 2.45 millionbarrels of oil per day in 2011. Rosneftegaz is the state-owned parent company ofRosneft.

BP had reached a preliminary deal with Rosneft on Oct. 22, saying then itwould negotiate toward a definitive agreement.

In a separate transaction, Rosneft also is buying AAR’s half of TNK-BP.—WESLEY LOY

PIPELINES & DOWNSTREAMU.S. backs XL: poll

A poll commissioned by the Canadian Association of Petroleum Producers haspointed to strong backing among Americans for Obama administration approvalof TransCanada’s Keystone XL pipeline “as soon as possible.”

Conducted by Anderson Insight, the poll of 2,406 Americans found that 82 per-cent believes pipelines are a safe way to deliver crude to market, 72 percent backKeystone XL, 74 percent see Canada as the oil supplier best able to “serve theeconomic interest” of the United States and 89 percent think Canada is one of themore environmentally responsible oil producers in the world.

CAPP president Dave Collyer said the results show that Americans viewCanadian-sourced crude as secure, a reliable source of supply, job-creating andeconomically beneficial to both countries.

“Canadian oil is the right oil for the United States, at the right time and from

see KEYSTONE XL POLL page 15

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PND selects Pickering as president, adds NottinghamPND Engineers Inc. said Nov. 28 that John

W. Pickering, P.E., M.B.A., was recently appoint-ed as the firm’s new president. Pickering hasmore than 35 years of professional engineeringexperience as a field and design engineer, con-struction manager and senior project manager,and has been with PND for more than 22years. Pickering has managed many integralprojects for PND and currently oversees PND’srole as the civil design engineers for the PointThomson Project on Alaska’s North Slope. Hisareas of expertise include arctic engineering,transportation engineering, hydrology, environmental engineering, and conceptual engineeringstudies.

In addition, PND Vice President Todd Nottingham, P.E. recently returned to the Anchorageoffice after spending 18 years with PND’s Seattle Office. Nottingham has been with PND since1986, and has worked primarily in the areas of marine structural design and bridge engineering.His recent projects include cruise ship docks, bulkheads, wave barriers, container terminals, and

bridges.PND is a dynamic civil engineering firm with more than 100 full-time employees, more than

half of whom are licensed engineers or surveyors. Founded in 1979, PND is headquartered inAnchorage with branch offices in Palmer and Juneau, Alaska, Seattle, Wash., and Fort Collins,Colo. PND is ranked among Alaska’s largest engineering firms and many of PND’s design solu-tions have received national awards and worldwide recognition.

Global Diving & Salvage Inc. recovers sunken fender Global Diving & Salvage Inc. said

Nov. 20 that in early March of 2012 thenorth fender on the Christy Lee oil plat-form, owned and operated by Hilcorp,experienced mechanical failure whichcaused it to plunge into approximately80 feet of water in Cook Inlet. Thefender structure mechanically raisedand lowered with the tide to keep visit-ing tankers properly fended during


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Oil Patch Bits

see OIL PATCH BITS page 13

TODD NOTTINGHAMJOHN W. PICKERING

CO

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“That’s why we’re in the Cook Inlet,”Lalicker said. “We’ve bought the propertiesand now we’re starting to deploy capitalagainst them and we’re running round thatlittle circle.”

Lalicker said that, in terms of reserves,production rates and value, Hilcorp haddoubled in size between 2006 and 2010,with the company having a target of dou-bling again by 2015. And having given eachof its employees a new car as a reward forachieving that first five-year growth objec-tive, the company has committed to payeach employee $100,000 if the objective for2015 is met, Lalicker said.

$230 millionAnd as part of its efforts to achieve its

expansion goals Hilcorp will have invested$230 million dollars in the Cook Inlet basinby the end of 2012. Around half of thatinvestment has gone into new developmentprojects, with much of the remainder —about 38 percent of the total — paying fora major refurbishment of the old Chevronassets.

“A lot of our energy has gone into justfixing broken stuff, and frankly that will bethe future for the next several years —there’s still a lot more broken stuff to befixed,” Lalicker said, adding that this type ofrefurbishment is typical of what is involvedin taking over big, old fields.

Examples of refurbishment includeHilcorp’s re-activation of the Drift River oilterminal on the west side of the Cook Inlet,an effort that has resulted in the resumptionof normal operations for the shipping of oilfrom the west side to the east side of theinlet. Other refurbishment has included thefixing of shut-in wells.

About 2 percent of Hilcorp’s expenditurehas paid for the disposal of what Lalickercharacterized as “old junk,” including theold drilling rigs on the offshore platforms,some of which date back to the 1960s.

“We spent a fair bit of time scraping thatstuff off this year and are working on gettingthe right equipment up here, so that we cando more drilling and workovers on thoseplatforms to get the production up,”Lalicker said.

About 8 percent of total expenditurewent on what Lalicker called “watchingother people work,” in other words the over-sight of activity at fields that Hilcorp co-owns but does not operate.

Increased productionHilcorp’s efforts have already borne fruit

in terms of increased oil production in thefields that the company operates, Lalickersaid. From January to early November pro-duction was up 8 percent at the McArthurRiver field; up 27 percent at Granite Point;up 36 percent at Trading Bay; and up 122percent at Swanson River, according to aproduction graph that Lalicker presented.

The picture has been less rosy for naturalgas production, with Hilcorp’s share of pro-duction down 11 percent at the BelugaRiver field; down 33 percent at TradingBay; and down 6 percent at Ninilchik. ButHilcorp does not operate these fields: Gasproduction is up 102 percent at the Hilcorp-operated Deep Creek field, and is up 39 per-cent across an aggregate of smaller Hilcorpfields, most of them on the west side of theinlet, Lalicker said.

Marathon assetsHilcorp is in the process of acquiring

Marathon’s Cook Inlet assets, an acquisi-

tion that would bring the Trading Bay andNinilchik fields to an effective 100 per-cent ownership by Hilcorp, Lalicker said.(Editor’s note: Marathon also operates thelarge Kenai gas field on the Kenai

Peninsula, as well as gas fields in theCannery Loop, Kasilof and Sterlingunits).

Marathon agreed on the sale of itsassets to Hilcorp in April but the sale hasyet to complete.

“We are slogging through the approvalprocess for that and we hope to have itclosed either late this year or early nextyear,” Lalicker said.

Plans for 2013Hilcorp expects to spend $150 million

to $200 million in 2013 on the Cook Inletassets that it already owns and another $50million on the Marathon assets, assumingthat the Marathon purchase goes through,Lalicker said. The focus in 2013 will be oilproduction offshore and at Swanson River.The company also recognizes the urgentneed for new gas production from theCook Inlet basin and, given the longer exe-cution time typical of offshore projects,has several onshore gas projects lined up.

“We’re feeling the pressure of gettinggas … and we’re working right now on it,”Lalicker said. “That’s why we’re focusingon the onshore side, because that’s wherewe can do it a deal faster than we can onthe offshore side.”

Overall, Hilcorp feels excited about theopportunities it sees in the Cook Inlet.

“It has truly world-class reservoirspresent … that were huge producers 20 or30 years ago, but really haven’t beenworked that hard in recent years,”Lalicker said. �


calls. The timeline for a prompt solution was critical, as delaying the arrival of tankers to theChristy Lee would subsequently result in substantial monetary loss.

Global, using sonar equipment to determine the exact location of the damaged fenderconcluded that there was sufficient water depth above the fender to allow the vessels to con-tinue to call at the berth; however a temporary system would need to be devised in order tokeep the platform operational.

Global developed a plan to install a temporary fender, successfully mobilized, fabricatedand installed the temporary fender system in just over two weeks, three days prior to thearrival of the next scheduled tanker.

In July, Global remobilized to the platform to recover the sunken fender, subcontractingwith Pacific Pile & Marine to provide a 500 ton crane. The 175.5 ton fender was lifted from theseafloor and loaded onto the barge and then transported to Nikiski, Alaska, for repairs andlater returned.

The repaired system has been fully operational since mid-October.


OIL PATCH BITS


HILCORP GROWTH Hilcorp applies for Deep Creek surveyHilcorp Alaska has applied to Alaska’s Division of Oil and Gas for a permit to con-

duct a 3-D seismic survey in and around the Deep Creek unit near Ninilchik onAlaska’s Kenai Peninsula. Deep Creek is a gas field that Hilcorp acquired in Januaryas part of the company’s purchase of Chevron’s Cook Inlet assets.

The planned survey would cover an area of about 32,000 acres, including 19,000acres of Deep Creek oil and gas leases. The survey area includes land owned by theState of Alaska, Cook Inlet Region Inc. and private landowners. In its permit applica-tion, Hilcorp says that it hopes to start the survey at the beginning of December andthat it anticipates the survey taking 120 days to complete.

However, the public comment period for the permit application does not end untilDec. 21.

“All project operations will occur onshore, outside of marine and tidal environ-ments, and during the winter season when frozen ground and/or snow cover will pro-vide protection of environmental and other resources in the area,” the application says.“Access will be via existing roads and trails, where possible, and via helicopter whereland access is restricted.”

The project will conclude by May 15, the application says.

Access straightforwardThe survey will involve detonating small, underground explosive charges at depths

of about 30 feet, with the charge holes plugged to prevent blowout and surface distur-bance. Because of extensive logging and previous 2-D seismic surveying in the area,Hilcorp anticipates access to much of the area being relatively straightforward,although the company expects to have to clear some brush and small trees at somelocations.

Track-mounted drilling rigs will drill the holes for the explosive charges, whileaccess to the survey area for setting charges and laying geophones, the devices usedto record subsurface echoes from the detonations, will be by tracked vehicle, helicop-ter and foot. Geophones will be laid at 220-foot intervals. Hilcorp anticipates usingexisting gravel pads for staging equipment and for fuel storage, the application says.

—ALAN BAILEY


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by oral statements in Victoria, Vancouverand Kelowna in the new year beforereturning to Prince Rupert on Feb. 4.

The panel is scheduled to release itsfindings in the last week of December2013, a deadline set by the federal gov-ernment.

Whatever action neededAlong with their participation in the

hearings, many First Nations have vowedto take whatever action is needed to pre-vent construction if Northern Gateway isapproved and to take their fight to thecourts.

A taste of what could be in store sur-faced Nov. 21 when a handful of membersfrom a First Nation evicted surveyorsworking on the C$1 billion Pacific TrailsPipeline, a key link in the planned Apache-operated Kitimat LNG project, then seizedequipment.

The group identifying itself as theUnis’tot’en clan of the Wet’suwet’enNation said the equipment will be helduntil Apache agrees to introduce “appro-priate lines of communication.”

“The Unis’tot’en clan has been dead setagainst all pipelines slated to cross throughtheir territories, which include (PacificTrails Pipeline), Enbridge’s NorthernGateway and many others,” Freda Huson,speaking for the group, said in a statement.

“As a result of the unsanctioned PTP

work …. the road leading into the territoryhas been closed to all industry activitiesuntil further notice,” she said.

No public negotiationsApache Canada spokesman Paul Wyke

told Petroleum News that some surveyorscomplied with a request by a “small groupof members from the Unis’tot’en” clan toleave the traditional territory.

He said the pipeline project is support-ed by 15 of the 16 aboriginal groups alongthe pipeline route and consultations areongoing with those communities.

But Wyke said Apache did not intend toseek a resolution of the problem by negoti-ating in public.

The eviction took place on land north-west of a deepwater port at Kitimat, whereKitimat LNG plans to build a liquefactionplant and tanker terminal. It is also the pro-posed site of a tanker port for NorthernGateway.

The Pacific Trails Pipeline receivedenvironmental approval in 2008 and wasexpected to be operational by 2015, butfaces delays if Kitimat partners Apache,Encana and EOG Resources are unable tosecure long-term sales contracts and find anew equity partner.

Wyke said a final investment decisionon Kitimat LNG will occur after a numberof milestones have been passed, includingthe settlement of sales contracts.

He said the partners have been “veryencouraged” by the way the project is“moving forward.”

Heated confrontations avoidedSo far, the various LNG proposals have

avoided the heated confrontations withFirst Nations that are dominating plans toship oil sands crude from Alberta byEnbridge for Northern Gateway andKinder Morgan for expansion of its TransMountain system.

Many aboriginal groups are basing theircase on a benchmark ruling by theSupreme Court of Canada, requiring feder-al and provincial governments to engage inmeaningful negotiations with First Nationsbefore major industrial projects areallowed to proceed on Native lands.

First Nations dissent has now extendedto southern Ontario, where two activistsfrom the Six Nations group told the citycouncil in Hamilton they are ready toengage in violent protest to blockEnbridge’s plan to carry 300,000 barrelsper day of crude on Line 9 to refineries inMontreal and Quebec City.

“We are paying attention to whatEnbridge is doing and we don’t like it,”said one of the activists, Wes Elliott. “Ifyou think we can’t do anything about it,you’re badly mistaken.”

Enbridge officials said the company haslearned a lot and taken proactive safety andemergency response measures since one ofits pipelines spilled 200,000 barrels ofcrude into Michigan’s Kalamazoo River in2010.

Enbridge advancing plansMeanwhile, despite the fierce resist-

ance to Northern Gateway and the loomingchallenge to Line 9, Enbridge is wasting notime advancing plans for other pipelines toget crude bitumen out of the Alberta oilsands.

It has announced an agreement withshippers to add another 570,000 bpd linkwithin Alberta by constructing a 36-inchline between Edmonton and a pipeline hubat Hardisty in Alberta, plus more tankageand terminal facilities at Edmonton, down-stream from the oil sands region, at a costof C$1.8 billion.

The new line will cover 110 miles, isscheduled for an in-service date of mid-2015 and will have the design potential forexpansion to 800,000 bpd, Enbridge said.

An application is expected to be filedwith Canada’s National Energy Board laterthis year, targeting a construction start inthe first quarter of 2014.

Stephen Wuori, Enbridge president ofliquids pipelines, said Enbridge’s objective

is to ensure it offers facilities and servicesto “maximize their value of shippers’ crudeoil.”

The proposed link is part of Enbridge’swider strategy to deliver rising volumes ofoil sands crude to refineries in Ontario andQuebec as well as U.S. markets on theTexas Gulf Coast, the Midwest and refiner-ies in the eastern U.S.

Additional capacity on Line 9 Enbridge also announced it is filing

with the National Energy Board to raisecapacity to 300,000 bpd on its reversedLine 9 to carry crude from WesternCanada and the Bakken into Quebec.

Vern Yu, vice president of business andmarket development for liquids pipelines,said the initial proposal to transport240,000 bpd from Nanticoke, Ontario, toMontreal was “significantly oversub-scribed,” and has prompted Enbridge toconsider a further expansion of Line 9 to340,000 bpd.

He said the initial shipments would beprimarily light crude to refineries ownedby Suncor Energy and Valero in QuebecCity, neither of which is designed toprocess heavier crudes.

He said Valero is considering movingcrude by rail or barge from Montreal, buthas asked Enbridge to consider extendingthe pipeline to Quebec City.

Yu said Enbridge has also filed anapplication with the U.S. Federal EnergyRegulatory Commission seeking approvalfor the commercial underpinnings of itsproposed Sandpiper project out of theNorth Dakota Bakken to carry 250,000-300,000 bpd from Fort Berthold toSuperior, Wis. — a plan he said has solidbacking from 20 shippers.

Enbridge is hoping to get a FERC go-ahead in the first quarter of 2013 and bringSandpiper into service by late 2015 orearly 2016.

Yu said Enbridge aims to build volumeson its total network to 3 million bpd fromabout 2 million bpd currently once its cur-rent basket of expansions, includingincreases to Alberta Clipper and SouthernAccess, and reduced bottlenecks in theChicago area, is completed.

The consulting firm of Deloitte hasestimated that Canadian producers are los-ing C$25 billion a year from transportationbottlenecks. �


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it had completed the second phase ofengineering on the project it launchedwith GVEA in August 2011. Havingreached that milestone, the company nowbelieves the Alaska IndustrialDevelopment and Export Authority andthe Alaska Energy Authority should studywhether the demand for LNG, outside ofthe amount Flint Hills intended to use,justifies the construction of a plant.

“We don’t think that we would buildthe plant for our needs and the needs ofother industrial users alone, so we willwait for AIDEA or AEA to do furtherinvestigation and present a proposal ifthey think that is appropriate,” Brose said,adding Flint Hills would share its engi-neering studies with the state if it wouldhelp move the project forward.

GVEA told the Fairbanks Daily News-Miner it would continue pursuing theproject, noting a 20-year gas supplyagreement it signed with BP Explorationin September.

Improved efficiencyUnder the August 2011 memorandum,

Flint Hills and GVEA planned to build aliquefaction plant at the Prudhoe Bay unitand truck LNG down the Dalton Highwayto a vaporization plant in North Pole,where the companies operate neighboringfacilities.

By getting a natural gas supply “atcost,” Flint Hills hoped to become morecompetitive and efficient, while GVEAhoped to be able to lower, or at least tem-per its rates.

With wide ranging Interior energyissues now being discussed at the statelevel, though, Flint Hills no longer saw theneed to pursue a project for its narrowinterests, Flint Hills Alaska spokesmanJeff Cook told Petroleum News. Internalchanges over the past year have improvedFlint Hills’ operating efficiency, he said.Those changes include installing a heatrecovery operation to maximize its energyuse, and idling one of its two remainingprocessing units. Since the idling of unitNo. 1, the remaining unit, No. 2, is nowrunning at full efficiency, according toCook. “We’ve improved our energy posi-tion,” he said.

Even with the changes, Flint Hills isinterested in natural gas, should it becomeavailable in the Interior at “competitive”prices, Cook said. Although the companywould need to retrofit some equipment toaccommodate the fuel, Cook described thechanges as minor.

Could speed up projectIn November, two Flint Hills sub-

sidiaries began permitting the $183.6 mil-lion project. The filings outlined a systemcapable of delivering 29.5 million cubicfeet of gas and 10,000 gallons of propaneper day to the Interior over 20 years, start-ing in 2016. (When they launched the proj-ect last summer, the two companies pro-jected a 2014 startup.)

The system would use 13,000-gallonlong-haul trucks to deliver the fuel to theregion.

The courtship between Flint Hills andGVEA promised to extend the mutuallybeneficial relationship between the com-panies at their neighboring facilities inNorth Pole. The Flint Hills refinery useselectricity produced by GVEA. TheGVEA plant in North Pole runs on naph-tha produced by Flint Hills (but wasdesigned to also operate on natural gas).

It remains to be seen how Flint Hills’decision will impact larger efforts to coor-dinate the various proposals for bringinggas to the second largest population centerin Alaska.

Before Flint Hills and GVEA signedtheir memorandum of understanding,Fairbanks Natural Gas LLC proposed asystem to truck LNG from the NorthSlope. The local distribution companyclaims to be ready for construction, butwants to align its intensions with those ofthe largest potential consumers in theregion, namely Flint Hills and GVEA.

Fairbanks Natural Gas and GVEA enti-ties have been in talks, according to bothsides.

Whether separately or together, bothFairbanks Natural Gas and GVEA havesaid they would seek state assistance onthe project. But Flint Hills, in its statement,said it “has been and continues to beopposed to all government mandates andsubsidies as they have reviewed the LNGproject and never requested State assis-tance for this project.”

Incoming GVEA President CoryBorgeson told the News-Miner the splitcould actually speed up the project. “Wemight be able to move faster. When you’vegot two parties working on things together,it takes longer to coordinate, come to con-sensus,” he said.

State funding likelyThe prospect of state funding promises

to alter the project considerably.Specifically, the Parnell administration

wants any project it funds to be open-access and wide-ranging. “If state fundsare used for a North Slope liquefactionfacility, we will assure long-term access tothat facility for other companies ... thatwant to purchase gas from producers andrun it through there,” Parnell told theindustry during his keynote address at the

on Koch’s interest to the other three compa-nies. The application didn’t disclose terms.

The companies moved for “expeditedconsideration,” requesting a decision byDec. 14.

In an order issued Nov. 21, the RCAnoted that under law, it wasn’t obliged tomake a final decision on the joint applica-tion until April 22. However, the commis-sion determined it could render a ruling byDec. 14, noting the companies had saidexpedited consideration was “necessary inorder to facilitate the continued operationand shipping capacity of TAPS and thatexpedited consideration will facilitate ayear-end closing date, thus allowing the par-ties to focus on strategic priorities in thenew year.”

Unocal seeks to interveneUnocal Pipeline Co. also is looking to

transfer or sell its stake in TAPS. At 1.3561percent, Unocal holds the smallest piece ofany of the five owners.

Unocal is believed to be negotiating asale and transfer of its operating authority tothe three major TAPS owners: BP, with a46.9263 percent interest; ConocoPhillips,28.2953 percent; and ExxonMobil, 20.3378percent.

While its own deal is pending, Unocalhas taken a keen interest in Koch’s pendingtransfer.

On Nov. 9, Unocal petitioned the regula-tory commission to intervene in the Kochproceeding.

“As the current TAPS owner with thesmallest ownership share, Unocal’s interestsare unique and cannot adequately be repre-sented by any other party in this proceed-ing,” Unocal told the commission. Thecompany noted it was the only TAPS ownernot a party to the joint Koch application.

“The Commission’s decision in this pro-ceeding may have a significant effect onUnocal because Unocal is also seeking towithdraw from TAPS,” Unocal’s petitionsaid. “Therefore, the decision in this pro-ceeding has the potential to affect the termsof Unocal’s withdrawal from TAPS.”

Koch on Nov. 16 filed an opposition toUnocal’s petition to intervene.

Under RCA regulations, intervention isappropriate only in matters that involve ahearing, and an application to transfer oper-ating authority does not require a hearing,Koch argued.

“Further, even if a hearing were required,Unocal failed to establish that its interven-tion would be conducive to the ends of jus-tice,” Koch told the commission.

Koch noted that the RCA “regulateseach TAPS carrier as if it owns a separatepipeline.”

As Unocal also is exiting the pipelineownership group, Unocal has no interest inacquiring any portion of Koch’s ownershipshare, Koch said.

The commission’s decision regarding theKoch transfer application won’t impactUnocal’s pipeline stake or the disposition ofits interest, “and thus Unocal has no interestin this docket that it needs to protect,” Kochargued.

“This conclusion is reinforced by thefact that Unocal has not finalized the termsof its TAPS interest transfer,” Koch added.“Unocal has previously indicated it may sellor transfer its TAPS interest to a third party,to one single TAPS owner, or to all remain-ing TAPS owners. Therefore, there is a rea-sonable possibility that Unocal’s transferwill look nothing like (Koch’s).”

RCA says noIn its Nov. 21 order, the RCA denied

Unocal’s motion to intervene, noting thatneither Unocal nor anyone else protested, oreven commented on, the proposed Kochtransfer, which was put out for public com-ment with a deadline of Nov. 9.

“No hearing is necessary in this pro-ceeding. Therefore, we deny Unocal’s peti-tion to intervene,” the RCA’s order said.

The regulatory commission already hasgranted both Koch and Unocal permissionto suspend service on their shares of TAPS.

Koch’s sole shipper was Flint HillsResources, a Koch subsidiary that operatesa refinery near Fairbanks.

—WESLEY LOY

the right country,” he said.Canada currently exports 2.5 mil-

lion barrels per day to the U.S. account-ing for 25 percent of all U.S. importsand leading all external suppliers.

CAPP said that although theInternational Energy Agency forecastsU.S. crude production could exceed

Saudi Arabia’s by 2020, the U.S. cur-rently requires crude imports toachieve energy self-sufficiency.

It said that even with increaseddomestic production, the U.S. is pro-jected to face a supply gap of 2.4 mil-lion bpd, which Canada could fill.

—GARY PARK


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fuel efficiency measures in the transporta-tion sector.

“The result is a continued fall in U.S. oilimports, to the extent that North Americabecomes a net oil exporter around 2030,”the IEA report said.

Further, under what the IEA calls itscentral scenario, the United States becomesa net exporter of natural gas by 2020, and is“almost self-sufficient in energy, in netterms, by 2035,” an IEA press release said.

The IEA describes itself as anautonomous organization working toensure reliable, affordable and clean ener-gy. It has 28 member countries, includingthe United States and Canada.

The prediction that the United Stateswill become the world’s top oil producer by2020 surprised many, and brought out afew skeptics.

Analysts with Deutsche Bank werereported to have produced an investor notearguing the United States won’t surpassSaudi Arabia as the No. 1 oil producer.They said U.S. policy restricting exports,coupled with sagging domestic demand foroil, could soften prices and discourageproject development.

“The idea that the U.S. could overtakeSaudi Arabia, even temporarily, is a stun-ning development after years of seeminglyinexorable declines in domestic oil produc-tion,” wrote Kevin Bullis, senior editor forthe MIT Technology Review.

As for the IEA’s conclusion that theUnited States could be nearly energy self-sufficient by 2035, that’s only after offset-ting oil imports with exports of coal andnatural gas, Bullis noted.

“To be truly energy independent,” hewrote, “the United States would have toinvest in technology for converting naturalgas and coal into the liquid fuels needed fortransportation, or have other technicalbreakthroughs, such as improved batteriesor biofuels, that would quickly reduce thedemand for oil.”

—WESLEY LOY


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annual Resource DevelopmentCouncil meeting in Anchorage onNov. 14.

While the LNG trucking projecthas been described as a way to bringthe benefits of gas to Fairbanks, “ifyou look ahead beyond that, it’s aboutgas for rural Alaska, it’s about gas forthe Richardson Highway. And thatliquefaction facility could pullpropane off and we could ship it thento communities along the river sys-tem,” Parnell said. “We could makethat transition from diesel in the com-munities to propane and gas. Wecould truck it down the RichardsonHighway as well to those communi-ties who feel they’ve been forgotten,who are not forgotten, but indeedcould have that cheaper energy aswell.”

One of the larger outstandingquestions is how any partnershipbetween the state, a private for-profitnatural gas distribution company anda member-owned not-for-profit elec-tric cooperative would be structured.Parnell said his administration would“continue working to utilize the pri-vate sector... to the extent we can, andwhere those are not working, then thestate will propose public-private part-nerships with private companies, per-haps through loans... financing,lower-cost financing to move theproject along.”

Whether those goals could bemeet through conditional funding, orwould require a state-owned project,could become clear when Parnellreleases his budget on Dec. 15.

IANGU is a wildcardAs these efforts progress, a newly

formed municipal utility is making itsdesires known.

The Interior Alaska Natural GasUtility plans to ask the Parnell admin-istration for $200 million for a NorthSlope liquefaction plant operatedunder a “transparent, cost-based com-modity pricing model,” according tothe News-Miner. As Petroleum Newswent to print, the utility board had notyet formalized its request, accordingto a spokeswoman.

The utility partnership of the citiesof Fairbanks and North Pole and theFairbanks North Star Borough toexpand gas use in the region alsoplans to ask for another $200 millionin grants and loans for a distributionsystem and to help homeowners con-vert their boilers, according to theNews-Miner, but may table some ofits requests until next year.

While the three municipalitiesformed the utility in October toaddress energy issues across theregion, it plans to begin by focusingon the city of North Pole. “We’refocusing on North Pole because it’sthe next most dense area outside theFairbanks area, it’s got the most airquality problems and it’s the otherend of town from the certificated areaserved by (Fairbanks Natural Gas),”the News-Miner quoted board mem-ber Bob Shefchik as saying. “Itmakes logical sense to start out thereand work your way toward town.” �

—Petroleum News Editor KristenNelson contributed to this article.


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